Many countries in the world have large deposits of oil sands, including the United States, but the world's largest deposits occur in Canada and Venezuela. Oil sands are a type of unconventional petroleum deposit, containing naturally occurring mixtures of sand, clay, water, and a dense and extremely viscous form of petroleum technically referred to as “bitumen,” but which can also be called heavy oil or tar.
Bitumen is a thick, sticky form of crude oil, so heavy and thick that it will not flow unless heated or diluted with lighter hydrocarbons. Often times, viscosity can be in excess of 1,000,000 cP. At room temperature, it is much like cold molasses.
Due to their high viscosity, these heavy oils are hard to mobilize, and they generally must be made to flow with heat and/or solvent before one can produce and transport them. One common way to heat bitumen is by injecting steam into the reservoir. Steam Assisted Gravity Drainage (SAGD) is the most extensively used technique for in situ recovery of bitumen resources in the McMurray Formation in the Alberta Oil Sands. In a typical SAGD process, shown in FIG. 1, two horizontal wells are vertically spaced by 4 to less than 10 meters (m). The production well is located near the bottom of the pay and the steam injection well is located directly above and parallel to the production well. In SAGD, steam is injected continuously into the injection well, where it rises in the reservoir and forms a steam chamber.
With continuous steam injection, the steam chamber will continue to grow upward and laterally into the surrounding formation. At the interface between the steam chamber and cold oil, steam condenses and heat is transferred to the surrounding oil. This heated oil becomes mobile and drains, together with the condensed water from the steam, into the production well due to gravity drainage within the steam chamber.
Vapor Extraction (VAPEX) is a relatively new process that can also be used to extract oil from heavy oil reservoirs. It is similar to SAGD, but instead of injecting hot steam into the oil reservoir, hydrocarbon solvents are used (see FIG. 2). The solvent gas is injected at its dew point, and the carrier gas is intended to raise the dew point of the solvent vapor so that it remains in the vapor phase at the reservoir pressure. A vapor chamber is formed and it propagates laterally. The main mechanism is improvement in mobility through viscosity reduction, but the process relies on molecular diffusion and mechanical dispersion for the transfer of solvent to the bitumen for viscosity reduction. Dispersion and diffusion are inherently slow, and therefore, are much less efficient than transfer of heat for viscosity reduction. However, the process uses much less heat and water than SAGD, and thus has some benefits.
Another developing enhanced oil recovery technique combines aspects of both SAGD and VAPEX. In expanding solvent-SAGD or ES-SAGD, also known as solvent assisted processes (SAP) or solvent co-injection (SCI), both steam and solvent are co-injected into the well. During the ES-SAGD process a small amount of solvent is co-injected with steam in a vapor phase. The solvent phase will have similar phase change properties as that of the steam. Suitable solvents are propane, butane, pentane, hexane, heptane, octane, naphtha, diluent and other light hydrocarbons and alkanes. Typically the injected solvent comprises 5-25 percent of the injected steam.
The solvent condenses with steam at the boundary of the steam chamber, diluting the oil and reduces its viscosity in conjunction with heat from the condensed steam. This process offers higher oil production rates and recovery with less energy and water consumption than those for the SAGD process, and less solvent usage than VAPEX. Experiments conducted with two-dimensional models for Cold Lake-type live oil showed improved oil recovery and rate, enhanced non-condensable gas production, lower residual oil saturation, and faster lateral advancement of heated zones (Nasr and Ayodele, 2006). A solvent assisted SAGD is shown in FIG. 3 and is described in U.S. Pat. Nos. 6,230,814; 6,591,908.
Combining solvent dilution and heat reduces oil viscosity much more effectively than using heat alone, uses less water and produces fewer overall greenhouse gas emissions. See FIG. 4 and FIG. 5.
Because of the high cost of the injected solvents, they are typically recovered from the reservoir and recycled or used as a diluent replacement for pipeline viscosity specifications. However, if too little solvent is recovered, the process can be uneconomic because the solvent is often more expensive than the produced heavy oil. The economics of a steam-solvent injection process thus depends on the enhancement of oil recovery as well as solvent recovery. The lower the solvent retention in the reservoir, the better the economics of the process.
As thermal-solvent recovery technologies continue to be developed, it is still unclear how to reduce solvent retention in the reservoir so that solvent costs can be minimized. Therefore, there is a need to find the optimal strategy to reduce solvent retention in the reservoir in ES-SAGD and similar processes, and thus improve the economics of oil production. This disclosure addresses one or more of those needs.